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News Release

Bonanza Creek Energy Announces Second Quarter 2018 Financial Results and Operational Update

DENVER, Aug. 08, 2018 (GLOBE NEWSWIRE) -- Bonanza Creek Energy, Inc. (NYSE: BCEI) (the "Company" or "Bonanza Creek") today announced its second quarter 2018 financial results and operating outlook and has posted an updated investor presentation on its corporate website.

Bonanza Creek delivered solid performance in the second quarter driven by strong production growth and lower capital spend. The Company is on track to grow Wattenberg production by approximately 25% year-over-year and 50% when comparing the fourth quarter of 2018 to the fourth quarter of 2017.

  • Second quarter sales volumes averaged 18.0 MBoe per day including the negative effects of a prior-period adjustment of 0.6 Mboe per day related to non-operated wells

  • Rapidly improving well performance yields over 1,000 economic drilling locations in Wattenberg

  • Full year 2018 Wattenberg production guidance raised while lowering full year capex guidance

  • Accretive Mid-Continent divestiture of $117 million(1) bolsters balance sheet, improves unit operating costs and focuses operations on highest returning opportunities

  • Well head pressures effectively managed via Rocky Mountain Infrastructure's ("RMI") multiple third-party gas processing optionality

  • Second quarter GAAP net income of $4.9 million, or $0.24 per diluted share; Adjusted net income(1) of $24.2 million, or $1.18 per diluted share

  •  Adjusted EBITDAX(2) of $34.8 million, 17% growth over first quarter 2018

(1) Effective date of February 1, 2018

(2) Non-GAAP measures, see attached reconciliation schedules at the end of this release.

"Bonanza Creek delivered a solid quarter, marked by consistently improving operational and financial performance. We continue to be encouraged by the strong well performance across our Wattenberg position. Through a combination of improving well productivity from more recent completion designs, and attention to our base, we are able to raise our full year 2018 production guidance while lowering our full-year capex," said Eric Greager, President and CEO.

"As we look further into this year and next, we expect to see strong production growth, improving unit costs and increased operating cash flow as we accelerate our pace of development. Our balance sheet remains strong. We are well-funded to execute on our capital plan which provides for approximately 25% Rockies production growth in 2018 and greater than 50% growth in 2019."

Second Quarter 2018 Results

During the second quarter of 2018, the Company reported average daily sales of 18.0 MBoe per day, which was at the low end of the Company's guidance range of 18.0 – 18.6 MBoe per day. Otherwise strong production during the quarter was impacted by a negative adjustment of 0.6 MBoe per day related to our interest in several months of production from two outside-operated pads. If not for this adjustment, second quarter production would have been at the high-end of guidance. The Company's second quarter reported sales increased 7% sequentially as we continue to see strong well performance from the recent completion designs and consistently low wellhead gathering pressures on the Company's RMI system. As a result of these factors, we are raising our full-year production guidance, pro-forma for the Mid-Continent divestiture, as detailed below. Product mix for the second quarter of 2018 was 58% oil, 20% NGLs, and 22% residue natural gas.

Net revenue for the second quarter of 2018 was $71.9 million, compared to $44.1 million for the second quarter of 2017. The increase in second quarter 2018 net revenue compared to 2017 was primarily a result of increased production and improved commodity pricing.  Crude oil accounted for approximately 85% of total revenue. Differentials for the Company's Wattenberg oil production during the quarter averaged approximately $6.39 per barrel off of NYMEX WTI. Corporate average realized prices for the second quarter of 2018 are presented below.

   
Average Realized Prices
(Before Derivatives)
 
  Three Months Ended
June 30, 2018
Oil (per Bbl) $63.67
Gas (per Mcf) $2.13
NGL (per Bbl) $19.05
Boe (Per Boe) $43.57
     

Lease operating expenses ("LOE") for the second quarter of 2018 were $11.3 million, compared to $9.4 million in the second quarter of 2017.  LOE on a unit basis for the second quarter of 2018 increased by 6.6% to $6.90 per Boe from $6.47 per Boe in the second quarter of 2017. Gas plant and midstream expenses for the second quarter of 2018 were $3.2 million, compared to $2.6 million in the second quarter of 2017. On a unit basis, gas plant and midstream expenses increased 10% to $1.98 per Boe for the second quarter of 2018 from $1.80 per Boe in the second quarter of 2017. Unit operating costs were impacted by decisions to pull forward certain planned activities and to pursue high-returning maintenance opportunities. They were also impacted by some cost inflation and environmental compliance costs required by the air emissions consent order in the Wattenberg Field. The Company’s accelerated compressor replacement program is now largely complete and will continue to ensure Bonanza Creek’s product flows while helping to reduce future operating costs. Additional spending on the company’s base optimization efforts (e.g. pipeline pigging and well servicing) have helped improve base production volumes. Cost pressures due to a busier operating environment and air emissions compliance costs are expected to continue through 2018 and are reflected in our revised LOE, gas plant and midstream expense guidance.

Below is a breakout of the Company's regional operating expenses for the second quarter of 2018.

 
  Three Months Ended June 30, 2018
  Wattenberg   Mid-Continent   Total Company
  ($M)   ($/Boe)   ($M)   ($/Boe)   ($M)   ($/Boe)
Lease operating expense $ 8,247     $ 6.01     $ 3,069     $ 11.45     $ 11,316     $ 6.90  
Gas plant and midstream operating expense $ 2,181     $ 1.59     $ 1,066     $ 3.98     $ 3,247     $ 1.98  
Total $ 10,428     $ 7.60     $ 4,135     $ 15.43     $ 14,563     $ 8.88  
                                               

The Company's general and administrative ("G&A") expense was $9.9 million for the second quarter of 2018, which includes $2.2 million in stock compensation. This represents a 48% decrease from the second quarter of 2017. Cash G&A expense, which excludes stock compensation, was $7.7 million for the quarter and is tracking at the low-end of the Company's full year 2018 guidance.

Reported net income for the second quarter of 2018 was $4.9 million, or $0.24 per diluted share. Adjusted net income for the second quarter of 2018 was $24.2 million, or $1.18 per diluted share.

Adjusted EBITDAX for the second quarter of 2018 was $34.8 million.

Cash G&A, Adjusted net income, and Adjusted EBITDAX are non-GAAP financial measures. Please refer to the respective reconciliations in the schedules at the end of this release for additional information about these measures.

The table below summarizes the Company's annual results as compared to previously provided guidance.

       
Guidance vs Actual Summary      
  2Q18 Guidance   2Q18 Actual
Production (MBoe/d) 18.0 - 18.6    18.0 
       
  Annual Guidance   YTD Actual
Lease operating expense ($/Boe) $5.00 - $6.00   $6.92 
Gas plant and midstream operating expense ($/Boe) $1.40 - $1.80   $2.18 
Cash G&A ($MM)* $33 - $35   $16 
Production taxes (% of pre-derivative realization) 7% - 8%    8%
CAPEX ($MM) $280 - $320   $95 
       
* Cash G&A guidance is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A. Please refer to the non-GAAP disclosure at the end of this release for information regarding cash G&A.
 

Production, Capital, and Expense Outlook

The Company is updating its 2018 annual guidance to account for strong well performance in the Wattenberg and the sale of the Mid-Continent operations on August 6, 2018.  Third quarter 2018 production and operating expense guidance is also being provided for the full company and pro-forma for the sale of the Mid-Continent operations. Below is a table summarizing the Company's production, capital, and expense guidance for the remainder of 2018.

           
Guidance Summary          
  Three Months Ended
September 30, 2018
(Pro-forma)(1)
Three Months Ended
September 30, 2018
  Twelve Months Ended
December 31, 2018
 
           
Production (MBoe/d) 16.6 - 17.2 17.4 - 18.0   17.4 - 18.0    
LOE ($/Boe) $4.40 - $4.80 $4.75 - $5.15   $5.50 - $5.90    
Midstream expense ($/Boe) $1.25 - $1.45 $1.45 - $1.65   $1.70 - $1.90    
Recurring cash G&A* ($MM)       $32.5 - $33.5    
Production taxes (% of pre-derivative realization)       7% - 8%  
Total CAPEX ($MM)       $275 - $295  
           
* Recurring Cash G&A is a non-GAAP measure that excludes the Company's stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A.  
(1) Pro-forma is the Company estimate for the third quarter of 2018 excluding results from the Mid-Continent operations.    
     

Operational Highlights

During the second quarter of 2018, the Company spud 12 gross (8.1 net) operated wells, ten of which were extended reach lateral ("XRL") wells, and completed 11 gross (11.0 net) operated wells, six of which were XRL wells.

The Company continues to be encouraged by its eight-well F26 pad on its western legacy acreage. These eight standard reach lateral ("SRL") wells have average cumulative production of 18.3 MBoe per 1,000 feet of lateral after 178 days of production. Additionally, the Company has finished completing and turned to production all eight XRL wells in the French Lake area. While two of the wells are currently hindered by mechanical issues, the Company is very pleased with the early results of the remaining six XRLs with results meeting or exceeding expectations.

The Company has provided updated production results for these wells in its August Investor Presentation, which is available on the Company's website.

The Company continued to benefit from multiple delivery points on the RMI system in the second quarter, including the Sterling interconnect which came online in the fourth quarter 2017. This delivery point flexibility, combined with consistent low line pressures on RMI, helped ensure minimal production curtailments. The Company entered into a new agreement with Cureton Front Range LLC (“Cureton”) whereby Cureton will gather and process gas from the Company’s northern acreage.  In addition to gathering and processing services, the new agreement provides flow assurance by adding 15 MMcf per day of firm gas processing capacity for up to twenty-five years. The Company also secured three years of downstream residue transportation from Cureton in order to support upcoming production needs. This improves the Company’s flexibility to manage system pressures across its Wattenberg position and provides the backbone infrastructure system to allow development of the northern acreage.

Upon completing the 2018 resource assessment and as a result of rapidly improving well performance, the Company has identified over 1,000 economic SRL equivalent locations in its Wattenberg position.

Financial Highlights

As of the end of the second quarter, the Company had liquidity of $153.7 million, which included cash on hand of $22.0 million and $131.7 million of borrowing capacity under its credit facility.  Pro forma for the Mid-Continent divestiture which closed on August 6, 2018, the Company had $256.6 million in liquidity.  The balance sheet strength and Wattenberg inventory provide the company with a strong position from which to deliver disciplined, return-oriented growth.

Commodity Derivative Position

The Company's current hedge position is summarized in the table below and reflects additional hedges the Company entered into through August 8, 2018. Subsequent to quarter-end, the Company entered into natural gas basis swaps between NYMEX Henry Hub price and the Colorado Interstate Gas (CIG) Rockies Natural Gas price, the index on which the majority of the Company's natural gas is sold.

           
    Crude Oil
(NYMEX WTI)
  Natural Gas
(NYMEX Henry Hub)
Natural Gas
(NYMEX Henry Hub)
    Bbls/day   Weighted
Avg. Price
per Bbl
  MMBtu/day   Weighted
Avg. Price
per MMBTU
MMBtu/day   Weighted Avg.
Basis Differential
to NYMEX Henry
Hub Price
per MMBtu
3Q18                      
Cashless Collar   2,000   $43.00/$53.50   13,600   $2.75/$3.32    —
Swap   5,000   $57.87        —
  Basis Swap      —     8,354   $0.67
4Q18                      
Cashless Collar   2,000   $43.00/$53.50   12,600   $2.75/$3.35    —
Swap   5,000   $58.07        —
  Basis Swap      —     12,600   $0.67
1Q19                      
Cashless Collar   2,000   $43.00/$54.53   7,600   $2.75/$3.22    —
Swap   5,000   $59.33        —
  Basis Swap      —     7,600   $0.67
2Q19                      
Cashless Collar   3,330   $51.81/$64.23   2,505   $2.75/$3.22    —
Swap   4,500   $58.32        —
3Q19                      
Swap   3,000   $55.00        —
4Q19                      
Swap   3,000   $55.00        —
                       

Conference Call Information

The Company will host a conference call to discuss these financial and operating results on August 9, 2018 at 10:00 a.m. Mountain Time (12:00 p.m. Eastern Time). A webcast of the live event, as well as a replay, will be available on the Investor Relations section of the Company’s website at www.bonanzacrk.com. Dial-in information for the conference call is included below.

     
Type Phone Number Passcode
Live Participant 877-793-4362 3289067
Replay 855-859-2056 3289067
     

About Bonanza Creek Energy, Inc.

Bonanza Creek Energy, Inc. is an independent oil and natural gas company engaged in the acquisition, exploration, development and production of onshore oil and associated liquids-rich natural gas in the United States. The Company’s assets and operations are concentrated in the Rocky Mountain region in the Wattenberg Field, focused on the Niobrara and Codell formations. The Company’s common shares are listed for trading on the NYSE under the symbol: “BCEI.” For more information about the Company, please visit www.bonanzacrk.com. Please note that the Company routinely posts important information about the Company under the Investor Relations section of its website.

Forward-Looking Statements

This press release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical facts, included in this press release that address activities, events or developments that the Company expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by the Company based on management’s experience, perception of historical trends and technical analyses, current conditions, anticipated future developments and other factors believed to be appropriate and reasonable by management. When used in this press release, the words “will,” “potential,” “believe,” “estimate,” “intend,” “expect,” “may,” “should,” “anticipate,” “could,” “plan,” “predict,” “project,” “profile,” “model” or their negatives, other similar expressions or the statements that include those words, are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These statements include statements regarding development and completion expectations and strategy; decreasing operating and capital costs; impact of the Company's reorganization; and updated 2018 guidance. Such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, that may cause actual results to differ materially from those implied or expressed by the forward-looking statements, including the following: changes in natural gas, oil and NGL prices; general economic conditions, including the performance of financial markets and interest rates; drilling results; shortages of oilfield equipment, services and personnel; operating risks such as unexpected drilling conditions; ability to acquire adequate supplies of water; risks related to derivative instruments; access to adequate gathering systems and pipeline take-away capacity; and pipeline and refining capacity constraints. Further information on such assumptions, risks and uncertainties is available in the Company’s SEC filings. We refer you to the discussion of risk factors in our Annual Report on Form 10-K for the year ended December 31, 2017, filed on March 15, 2018, and other filings submitted by us to the Securities Exchange Commission. The Company’s SEC filings are available on the Company’s website at www.bonanzacrk.com and on the SEC’s website at www.sec.gov. All of the forward-looking statements made in this press release are qualified by these cautionary statements. Any forward-looking statement speaks only as of the date on which such statement is made, including guidance, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required by applicable law.

For further information, please contact:
Doug Atkinson
Senior Manager, Investor Relations
720-225-6690
datkinson@bonanzacrk.com

 
Schedule 1: Statements of Operations
(in thousands, expect for per share amounts, unaudited)
 
  Successor     Predecessor
  Three Months Ended
June 30, 2018
  April 29, 2017 through
June 30, 2017
    April 1, 2017 through
April 28, 2017
Operating net revenues:            
Oil and gas sales $ 71,872     $ 28,114       $ 16,030  
Operating expenses:            
Lease operating expense 11,316     6,153       3,203  
Gas plant and midstream operating expense 3,247     1,762       836  
Gathering, transportation and processing 1,660            
Severance and ad valorem taxes 6,071     2,408       1,352  
Exploration 221     359       292  
Depreciation, depletion and amortization 9,564     4,836       6,853  
Abandonment and impairment of unproved properties(1) 2,477            
General and administrative (including $2,184, $7,949 and
$391, respectively, of stock-based compensation)
9,917     16,139       2,998  
Total operating expenses 44,473     31,657       15,534  
Income (loss) from operations 27,399     (3,543 )     496  
Other income (expense):            
Derivative loss (22,012 )          
Interest expense (805 )   (195 )     (1,088 )
Reorganization items, net           97,811  
Other income (expense) 277     158       (283 )
Total other income (expense) (22,540 )   (37 )     96,440  
Income (loss) from operations before taxes 4,859     (3,580 )     96,936  
Income tax benefit (expense)            
Net income (loss) $ 4,859     $ (3,580 )     $ 96,936  
             
Comprehensive income (loss) $ 4,859     $ (3,580 )     $ 96,936  
             
Basic net income (loss) per common share $ 0.24     $ (0.18 )     $ 1.88  
             
Diluted net income (loss) per common share $ 0.24     $ (0.18 )     $ 1.85  
             
Basic weighted-average common shares outstanding 20,488     20,369       49,902  
             
Diluted weighted-average common shares outstanding 20,603     20,369       50,486  
                   

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to the standard amortization of unproved properties within the Wattenberg Field during the Current Successor quarter.   

         
  Successor     Predecessor
  Six Months Ended
June 30, 2018
  April 29, 2017 through
June 30, 2017
    January 1, 2017 through
April 28, 2017
Operating net revenues:            
Oil and gas sales $ 136,064     $ 28,114       $ 68,589  
Operating expenses:            
Lease operating expense 21,775     6,153       13,128  
Gas plant and midstream operating expense 6,860     1,762       3,541  
Gathering, transportation and processing 3,998            
Severance and ad valorem taxes 11,303     2,408       5,671  
Exploration 250     359       3,699  
Depreciation, depletion and amortization 17,072     4,836       28,065  
Abandonment and impairment of unproved properties(1) 4,979            
Unused commitments 21           993  
General and administrative (including $3,192, $7,949 and
$2,116, respectively, of stock-based compensation)
19,451     16,139       15,092  
Total operating expenses 85,709     31,657       70,189  
Income (loss) from operations 50,355     (3,543 )     (1,600 )
Other income (expense):            
Derivative loss (30,754 )          
Interest expense (1,162 )   (195 )     (5,656 )
Reorganization items, net           8,808  
Other income 290     158       1,108  
Total other income (expense) (31,626 )   (37 )     4,260  
Income (loss) from operations before taxes 18,729     (3,580 )     2,660  
Income tax benefit (expense)            
Net income (loss) $ 18,729     $ (3,580 )     $ 2,660  
             
Comprehensive income (loss) $ 18,729     $ (3,580 )     $ 2,660  
             
Basic net income (loss) per common share $ 0.91     $ (0.18 )     $ 0.05  
             
Diluted net income (loss) per common share $ 0.91     $ (0.18 )     $ 0.05  
             
Basic weighted-average common shares outstanding 20,471     20,369       49,559  
             
Diluted weighted-average common shares outstanding 20,538     20,369       50,971  
                   

Note: The Predecessor Company followed the two-class method when computing the basic and diluted net income (loss) per share, which allocates earnings between common shareholders and unvested participating securities. The Successor Company follows the treasury stock method to compute basic and diluted net income (loss) per share. Please refer to Note 12 – Earnings per Share in the Form 10-Q, for a detailed calculation.
(1) The Company incurred impairment charges relating to non-core leases expiring and the standard amortization of unproved properties within the Wattenberg Field during the Current Successor Period.

 
Schedule 2: Statements of Cash Flows
(in thousands, unaudited)
 
  Successor   Successor     Predecessor
  Three Months Ended
June 30, 2018
  April 29, 2017 through
June 30, 2017
    April 1, 2017 through
April 28, 2017
Cash flows from operating activities:            
Net income (loss) $ 4,859     $ (3,580 )     $ 96,936  
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
           
Depreciation, depletion and amortization 9,564     4,836       6,853  
Non-cash reorganization items           (101,501 )
Abandonment and impairment of unproved properties 2,477            
Well abandonment costs and dry hole expense     64       230  
Stock-based compensation 2,184     7,949       391  
Amortization of deferred financing costs and debt premium           374  
Derivative loss 22,012            
Derivative cash settlements (7,310 )          
Other     5       (365 )
Changes in current assets and liabilities:            
Accounts receivable (4,618 )   6,420       (2,826 )
Prepaid expenses and other assets (2,467 )   270       1,499  
Accounts payable and accrued liabilities (323 )   (19,338 )     (36,972 )
Settlement of asset retirement obligations (132 )   (459 )     (155 )
Net cash provided by (used in) operating activities 26,246     (3,833 )     (35,536 )
Cash flows from investing activities:            
Acquisition of oil and gas properties (1,197 )   (4,982 )     (6 )
Exploration and development of oil and gas properties (53,818 )   (4,913 )     (1,698 )
Proceeds from sale of oil and gas properties            
Additions to property and equipment - non oil and gas (177 )   (161 )     (253 )
Net cash used in investing activities (55,192 )   (10,056 )     (1,957 )
Cash flows from financing activities:            
Proceeds from credit facility 45,000            
Payments to credit facility           (191,667 )
Proceeds from sale of common stock           207,500  
Proceeds from exercise of stock options 968            
Payment of employee tax withholdings in exchange for the return of common stock (794 )   (2,080 )     (92 )
Net cash provided by (used in) financing activities 45,174     (2,080 )     15,741  
Net change in cash, cash equivalents and restricted cash 16,228     (15,969 )     (21,752 )
Cash, cash equivalents and restricted cash:            
Beginning of period 5,840     68,406       90,158  
End of period $ 22,068     $ 52,437       $ 68,406  
                         


 
  Successor     Predecessor
  Six Months Ended
June 30, 2018
  April 29, 2017 through
June 30, 2017
    January 1, 2017 through
April 28, 2017
Cash flows from operating activities:            
Net income (loss) $ 18,729     $ (3,580 )     $ 2,660  
Adjustments to reconcile net income (loss) to net cash provided by
(used in) operating activities:
           
Depreciation, depletion and amortization 17,072     4,836       28,065  
Non-cash reorganization items           (44,160 )
Abandonment and impairment of unproved properties 4,979            
Well abandonment costs and dry hole expense     64       2,931  
Stock-based compensation 3,192     7,949       2,116  
Amortization of deferred financing costs and debt premium           374  
Derivative loss 30,754            
Derivative cash settlements (11,622 )          
Other 172     5       18  
Changes in current assets and liabilities:            
Accounts receivable (20,376 )   6,420       (6,640 )
Prepaid expenses and other assets 935     270       963  
Accounts payable and accrued liabilities (889 )   (19,338 )     (5,880 )
Settlement of asset retirement obligations (797 )   (459 )     (331 )
Net cash provided by (used in) operating activities 42,149     (3,833 )     (19,884 )
Cash flows from investing activities:            
Acquisition of oil and gas properties (1,295 )   (4,982 )     (445 )
Exploration and development of oil and gas properties (91,482 )   (4,913 )     (5,123 )
Proceeds from sale of oil and gas properties 20            
Additions to property and equipment - non oil and gas (280 )   (161 )     (454 )
Net cash used in investing activities (93,037 )   (10,056 )     (6,022 )
Cash flows from financing activities:            
Proceeds from credit facility 60,000            
Payments to credit facility           (191,667 )
Proceeds from sale of common stock           207,500  
Proceeds from exercise of stock options 968            
Payment of employee tax withholdings in exchange for the return of common stock (794 )   (2,080 )     (427 )
Net cash provided by (used in) financing activities 60,174     (2,080 )     15,406  
Net change in cash, cash equivalents and restricted cash 9,286     (15,969 )     (10,500 )
Cash, cash equivalents and restricted cash:            
Beginning of period 12,782     68,406       78,906  
End of period $ 22,068     $ 52,437       $ 68,406  
                         


 
Schedule 3: Condensed Consolidated Balance Sheets
 
  Successor
  June 30, 2018   December 31, 2017
ASSETS      
Current assets:      
Cash and cash equivalents $   21,989     $ 12,711  
Accounts receivable:      
Oil and gas sales 38,830     28,549  
Joint interest and other 13,926     3,831  
Prepaid expenses and other 5,620     6,555  
Inventory of oilfield equipment 1,434     1,019  
Derivative assets 39     488  
Total current assets 81,838     53,153  
Property and equipment (successful efforts method):      
Proved properties 552,858     555,341  
Less: accumulated depreciation, depletion and amortization (29,703 )   (17,032 )
Total proved properties, net 523,155     538,309  
Unproved properties 179,735     183,843  
Wells in progress 52,747     47,224  
Oil and gas properties held for sale, net of accumulated depreciation,
depletion and amortization of $2,583 in 2018
82,328      
Other property and equipment, net of accumulated depreciation
of $2,722 in 2018 and $2,224 in 2017
4,488     4,706  
Total property and equipment, net 842,453     774,082  
Long-term derivative assets     6  
Other noncurrent assets 3,151     3,130  
Total assets $   927,442     $ 830,371  
LIABILITIES AND STOCKHOLDERS’ EQUITY      
Current liabilities:      
Accounts payable and accrued expenses $ 50,242     $ 62,129  
Oil and gas revenue distribution payable 20,355     15,667  
Derivative liability 28,416     11,423  
Total current liabilities 99,013     89,219  
       
Long-term liabilities:      
Credit facility 60,000      
Ad valorem taxes 19,803     11,584  
Long-term derivative liability 4,657     2,972  
Asset retirement obligations for oil and gas properties 28,154     38,262  
Asset retirement obligations for oil and gas properties held for sale 5,386      
Total liabilities 217,013     142,037  
       
Commitments and contingencies      
       
Stockholders’ equity:      
Preferred stock, $.01 par value, 25,000,000 shares authorized, none outstanding      
Common stock, $.01 par value, 225,000,000 shares authorized, 20,534,799 and
20,453,549 issued and outstanding in 2018 and 2017, respectively
4,286     4,286  
Additional paid-in capital 692,434     689,068  
Retained earnings (deficit) 13,709     (5,020 )
Total stockholders’ equity 710,429     688,334  
Total liabilities and stockholders’ equity $ 927,442     $ 830,371  
               


 
Schedule 4: Volumes and Realized Prices (Before and After the Effect of Commodity Hedges)
(unaudited)
 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
  2018   2017   2018   2017
Wellhead Volumes and Prices              
               
Crude Oil and Condensate Sales Volumes (Bbl/d)              
Rocky Mountains 8,866     6,189     8,575     6,690  
Mid-Continent 1,600     1,845     1,633     1,889  
Total 10,466     8,034     10,208     8,579  
               
Crude Oil and Condensate Realized Prices ($/Bbl)              
Rocky Mountains $ 63.05     $ 43.94     $ 60.15     $ 45.94  
Mid-Continent $ 67.12     $ 47.69     $ 64.69     $ 49.65  
Composite $ 63.67     $ 44.80     $ 60.87     $ 46.76  
Composite (after derivatives) $ 55.99     $ 44.80     $ 54.47     $ 46.76  
               
Natural Gas Liquids Sales Volumes (Bbl/d)              
Rocky Mountains 3,126     3,046     2,772     3,167  
Mid-Continent 441     452     444     471  
Total 3,567     3,498     3,216     3,638  
               
Natural Gas Liquids Realized Prices ($/Bbl)              
Rocky Mountains $ 17.06     $ 16.10     $ 19.34     $ 15.90  
Mid-Continent $ 33.13     $ 20.84     $ 30.92     $ 23.32  
Composite $ 19.05     $ 16.71     $ 20.94     $ 16.86  
Composite (after derivatives) $ 19.05     $ 16.71     $ 20.94     $ 16.86  
               
Natural Gas Sales Volumes (Mcf/d)              
Rocky Mountains 18,511     20,144     18,385     20,786  
Mid-Continent 5,421     6,067     5,444     6,249  
Total 23,932     26,211     23,829     27,035  
               
Natural Gas Realized Prices ($/Mcf)              
Rocky Mountains $ 1.96     $ 2.18     $ 2.29     $ 2.29  
Mid-Continent $ 2.70     $ 3.06     $ 2.98     $ 3.15  
Composite $ 2.13     $ 2.38     $ 2.45     $ 2.49  
Composite (after derivatives) $ 2.13     $ 2.38     $ 2.50     $ 2.49  
               
Crude Oil Equivalent Sales Volumes (Boe/d)              
Rocky Mountains 15,077     12,592     14,412     13,322  
Mid-Continent 2,945     3,308     2,985     3,402  
Total 18,022     15,900     17,397     16,724  
               
Crude Oil Equivalent Sales Prices ($/Boe)              
Rocky Mountains $ 43.02     $ 28.98     $ 42.43     $ 30.43  
Mid-Continent $ 46.40     $ 35.05     $ 45.43     $ 36.60  
Composite $ 43.57     $ 30.24     $ 42.95     $ 31.68  
Composite (after derivatives) $ 39.11     $ 30.24     $ 39.26     $ 31.68  
               
Total Sales Volumes (MBoe) 1,640.0     1,446.9     3,148.8     3,026.9  
                       


 
Schedule 5: Per unit operating margins
(unaudited)
 
  Three Months Ended June 30,   Six Months Ended June 30,
  2018   2017   Percent
Change
  2018   2017   Percent
Change
Production                      
Oil (MBbl) 952     731     30 %   1,848     1,553     19 %
Gas (MMcf) 2,178     2,385     (9 )%   4,313     4,893     (12 )%
NGL (MBbl) 325     318     2 %   582     659     (12 )%
Equivalent (MBoe) 1,640     1,447     13 %   3,149     3,027     4 %
                       
Realized pricing (before derivatives)                      
Oil ($/Bbl) $ 63.67     $ 44.80     42 %   $ 60.87     $ 46.76     30 %
Gas ($/Mcf) $ 2.13     $ 2.38     (11 )%   $ 2.45     $ 2.49     (2 )%
NGL ($/Bbl) $ 19.05     $ 16.71     14 %   $ 20.94     $ 16.86     24 %
Equivalent ($/Boe) $ 43.57     $ 30.24     44 %   $ 42.95     $ 31.68     36 %
                       
Per Unit Costs ($/Boe)                      
Realized price equivalent (before derivatives) $ 43.57     $ 30.24     44 %   $ 42.95     $ 31.68     36 %
Lease operating expense 6.90     6.47     7 %   6.92     6.37     9 %
Gathering, transportation and processing 1.01         %   1.27         %
Gas plant and midstream operating expense 1.98     1.80     10 %   2.18     1.75     25 %
Severance and ad valorem 3.70     2.60     42 %   3.59     2.67     34 %
Cash general and administrative 4.72     7.46     (37 )%   5.16     6.99     (26 )%
Total cash operating costs $ 18.31     $ 18.33     %   $ 19.12     $ 17.78     8 %
Cash operating margin (before derivatives) $ 25.26     $ 11.91     112 %   $ 23.83     $ 13.90     71 %
Derivative cash settlements (4.46 )       %   (3.69 )       %
Cash operating margin (after derivatives) $ 20.80     $ 11.91     75 %   $ 20.14     $ 13.90     45 %
                       
Non-cash items                      
Non-cash general and administrative $ 1.33     $ 5.76     (77 )%   $ 1.01     $ 3.33     (70 )%
                                           

Schedule 6: Adjusted Net Income
(in thousands, except per share amounts, unaudited)

Adjusted net income is a supplemental non-GAAP financial measure that is used by management to present recurring profitability that is more comparable between periods by excluding items that are non-recurring in nature or items which are not easily estimable. Management believes adjusted net income provides external users of the Company's consolidated financial statements such as industry analysts, investors, creditors, and rating agencies with additional information to assist in their analysis of the Company. The Company defines adjusted net income as net income after adjusting first for (1) the impact of certain non-cash items and one-time transactions and then (2) the non-cash and one time items’ impact on taxes based on a tax rate that approximates the Company's effective tax rate in each period. Adjusted net income is not a measure of net income as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of adjusted net income.

         
    Three Months Ended
June 30,
  Six Months Ended
June 30,
    2018   2017   2018   2017
Net income (loss)   $ 4,859     $ 93,356     $ 18,729     $ (920 )
Adjustments to net income:                
Derivative loss   22,012         30,754      
Derivative cash settlements   (7,310 )       (11,622 )    
Abandonment and impairment of unproved properties   2,477         4,979      
Exploratory dry hole expense       294         2,995  
Unused commitments           21     993  
Stock-based compensation (1)   2,184     8,340     3,192     10,065  
Reorganization items, net       (97,811 )       (8,808 )
Pre-petition advisory fees (1)               683  
Post-petition restructuring fees (1)       1,422         1,422  
Total adjustments before taxes   19,363     (87,755 )   27,324     7,350  
Income tax effect                
Total adjustments after taxes   $ 19,363     $ (87,755 )   $ 27,324     $ 7,350  
                 
Adjusted net income   $ 24,222     $ 5,601     $ 46,053     $ 6,430  
Adjusted net income per diluted share (2)   $ 1.18     $ 0.27     $ 2.24     $ 0.32  
                 
Diluted weighted-average common shares outstanding (2)   20,603     20,369     20,538     20,369  
                 
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
(2) For the three- and six-month periods ended June 30, 2017, the Company used the Successor's diluted weighted average share count to calculate adjusted net income per diluted share.
 

Schedule 7: Adjusted EBITDAX
(in thousands, unaudited)

Adjusted EBITDAX is a supplemental non-GAAP financial measure that is used by management to provide a metric of the Company's ability to internally generate funds for exploration and development of oil and gas properties. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes adjusted EBITDAX provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-GAAP financial measure of Adjusted EBITDAX.

         
    Three Months Ended June 30,   Six Months Ended June 30,
    2018   2017   2018   2017
Net income (loss)   $ 4,859     $ 93,356     $ 18,729     $ (920 )
Exploration   221     651     250     4,058  
Depreciation, depletion and amortization   9,564     11,689     17,072     32,901  
Abandonment and impairment of unproved properties   2,477         4,979      
Unused commitments           21     993  
Stock-based compensation (1)   2,184     8,340     3,192     10,065  
Interest expense   805     1,283     1,162     5,851  
Derivative loss   22,012         30,754      
Derivative cash settlements   (7,310 )       (11,622 )    
Pre-petition advisory fees (1)               683  
Post-petition restructuring fees (1)       1,422         1,422  
Reorganization items, net       (97,811 )       (8,808 )
Adjusted EBITDAX   $ 34,812     $ 18,930     $ 64,537     $ 46,245  
                 
(1) Included as a portion of general and administrative expense in the consolidated statements of operations.
 

Schedule 8: Cash G&A
(in thousands, unaudited)

Cash G&A is a supplemental non-GAAP financial measure that is used by management to provide only the cash portion of its G&A expense, which can be used to evaluate cost management and operating efficiency on a comparable basis from period to period. Management believes cash G&A provides external users of the Company’s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines cash G&A as GAAP general and administrative expense exclusive of the Company's stock based compensation and one-time charges, such as severance costs and advisor fees. The Company refers to cash G&A to provide typical cash G&A costs that are planned for in a given period. Cash G&A is not a fully inclusive measure of general and administrative expense as determined by GAAP.

The following table presents a reconciliation of the GAAP financial measure of general and administrative expense to the non-GAAP financial measure of cash G&A.

         
    Three Months Ended June 30,   Six Months Ended June 30,
    2018   2017   2018   2017
General and administrative   $ 9,917     $ 19,137     $ 19,451     $ 31,231  
Stock-based compensation   (2,184 )   (8,340 )   (3,192 )   (10,065 )
Cash G&A   $ 7,733     $ 10,797     $ 16,259     $ 21,166  
Post-petition restructuring fees       (1,422 )       (1,422 )
Other non-recurring expense       (184 )       (184 )
Recurring Cash G&A   $ 7,733     $ 9,191     $ 16,259     $ 19,560  

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